Wind and nuclear and the increasing irrelevance of capacity factor in Ontario – 2014 February

By: Donald Jones, P.Eng., retired nuclear industry engineer.

The answer given by wind promoters to the intermittency question of wind, and to bolster their claim that wind (and now, they admit, with the help of frackgas) can replace nuclear in Ontario, is to say that any interruption in wind is no different from a nuclear unit coming unexpectedly off line. They also point out that the loss of wind does not occur suddenly like a nuclear unit and the geographic distribution of wind turbines means that wind is always generating somewhere. Wrong on all accounts. Wind is, and will increasingly be, a hindrance to the Ontario grid and it is also making the capacity factor of generators on the grid irrelevant as an indication of performance and reliability.

The Ontario grid has to maintain an operating reserve, some spinning and some not spinning, to handle the loss of the largest generating unit on the grid and loss of half the amount of the second largest unit (see Note 1). This typically means about 1,500 megawatts (MW) of operating reserve being available within 30 minutes with some of this being available within 10 minutes. A Darlington unit at 880 MW to the grid is the largest nuclear unit on the grid so normal operating reserve can easily handle a nuclear unit coming suddenly and unexpectedly off line. With wind likely to be over 6,000 MW nameplate capacity in the next few years wind is a different story. Operating reserve cannot be used to mitigate losses in wind production since that would make it unavailable for its intended use. While right now a reduction in wind output of 50 percent, say from around 2,000 MW to 1,000 MW, could be handled a reduction of 3,000 MW or more in the future would not. While the loss of wind generation would be less sudden than a loss of a nuclear unit it is still relatively sudden when considering that 3,000 MW or more of generation now has to be cobbled together over a relatively short period of time to replace the lost wind (see Note 2). The stability of the grid could depend on the accuracy of the information in the centralized weather forecasting system used by the Independent Electricity System Operator (IESO).

All gas-fired units on the grid, except for one flexible 393 MW simple cycle station, are relatively inflexible combined cycle gas turbine (CCGT) units or inflexible combined heat and power plants. Bearing in mind the time it takes to bring CCGT units into their dispatchable power range even from a warm condition and the limited amount of hydro storage available cobbling together enough replacement generation after loss of significant wind generation will be a major issue. It will result in limiting the amount of wind on the grid to what can be replaced in a short period of time. This means curtailment of wind will always be the case on windy high demand days and the wind generators would still have to be paid for their deemed generation (that did not get on the grid), based on the information provided to the IESO by the centralized weather forecasting system. This situation becomes more than a hindrance if wind generation starts to fall off during the morning ramp up to meet the increasing grid demand. A similar situation arises in the afternoon when solar is fading just as the late afternoon ramp up is getting underway. Besides wind curtailment the only other solution to accommodate more wind on the grid would be to add a few thousand MW of quick start simple cycle gas turbines to the operating reserve, call it wind reserve, that would not otherwise be needed (see Note 2). That makes no economic or environmental sense. Loss of wind is a lot worse than loss of a nuclear unit.

Wind output on the IESO controlled grid varies widely from near 2,000 MW to 20 MW or less despite geographic spacing of wind sites showing that spacing does not help. Unlike wind nuclear has very few unplanned interruptions. Data from the Canadian Nuclear Safety Commission (CNSC) for 2012 (latest year available) show the number of forced outages as three for Bruce A, one for Bruce B, four for Darlington, four for Pickering A and three for Pickering B. Not all forced outages (outages that are not planned) bring a unit suddenly off line, some can be delayed for a few hours to a more convenient time. CNSC also reported automatic reactor trips, that will put units immediately off line, as two for Bruce A (could be due to teething problems with return to service of units 1 and 2 in second half of 2012), none for Bruce B, one for Darlington, one for Pickering A and one for Pickering B. Reactor trips will keep a unit off line for two or three days.

Assigning a capacity factor, which normally is a measure of performance, to wind is meaningless since output in MW varies so much and is usually not there when needed and there in abundance when not needed. Subsequent to 2013 September it became more meaningless when the IESO was allowed to curtail wind output during periods of Surplus Baseload Generation (SBG) mostly caused by and excess wind generation when not needed during low demand periods. For what it’s worth the annual average capacity factor for wind in Ontario could be less than 30 percent. Nuclear units in general are expected to run continuously and are only off line due to forced or planned outages so capacity factor is a true representation of unit performance and reliability. However in Ontario nuclear units have been, and still are, manoeuvred and even shutdown to mitigate SBG on instructions from the IESO. New build nuclear in Ontario will be highly flexible and be able to load cycle and load follow and provide automatic generation control (see Note 3). This means capacity factor will not be a true indicator of unit performance and another metric, the availability factor, would have to be used. The availability factor is the percentage of time, in a year say, that the unit is available for production and manoeuvring. In the case of wind the availability factor depends on nature, the wind, and is meaningless. Having a wind generator with a 98 percent availability factor only when the wind is blowing does not inspire confidence in the middle of an Ontario winter.

Bruce nuclear units have been doing significant load reductions (see Note 4) and are even shutdown when dispatched by the IESO to mitigate periods of SBG so their capacity factors will be reduced. Other Ontario nuclear units that cannot presently be manoeuvred to reduce output have been shutdown to mitigate SBG so their capacity factors would also be reduced. Capacity factors in 2012 (latest year available) based on data in the Canadian Nuclear Society’s 2013 Nuclear Canada Yearbook were, 54.6 percent for units 3 and 4 at Bruce A (units 1 and 2 of Bruce A were returned to service in the second half of 2012), 95.9 percent for four unit Bruce B, 92.5 percent for four unit Darlington, 69.1 percent for Pickering A units 1 and 4 (units 2 and 3 permanently shutdown) and 81.7 percent for four unit Pickering B. Average annual nuclear capacity factor for these 16 operating units in 2012 would be 83.0 percent. Darlington unit 4 together with CANDU 6 power plants Cernavoda unit 2 in Romania and Wolsong unit 4 in South Korea were in the world’s top 25 performers for 2012. One of India’s pressurized heavy water reactors of the pressure tube CANDU type, Rajasthan unit 4, was also in the top 25.

The presence of wind (and solar) on the Ontario grid, as well as affecting nuclear generation, reduces the operating time of the CCGT units so capacity factor does not reflect their performance anymore. CCGTs are base load and sometimes intermediate load machines operating at constant output but due to the variability of wind they are being dispatched to stop and start and manoeuvre. The availability factor, a metric of reliability to start and manoeuvre and run on demand, should be used instead of capacity factor. While capacity factor could still be used for Levelized Unit Energy Cost calculations the availability factor would now be a better metric for assessing the performance of all Ontario generating units because of the presence of large amounts of wind generation on the grid.

Notes

1. The following is from IESO website.

Operating Reserve and Reliability.
When the IESO determines operating reserve requirements, it must adhere to reliability standards established by authorities such as the North American Electric Reliability Council (NERC) and the Northeast Power Coordinating Council (NPCC). Operating reserve requirements are based on the largest single unexpected event (contingency) plus half of the second largest contingency that could occur under a given IESO-controlled grid operating configuration. Typically, this means the loss of the two largest generators. The IESO usually schedules between 1,380 and 1,580 megawatts of OR at any given time (this is the sum of the ten-minute and thirty-minute requirements).

Types of Operating Reserve.
The IESO administers markets for three classes of OR: 10-minute spinning, 10-minute non-spinning and 30-minute OR. 10-minute spinning and non-spinning OR must be provided by resources whose energy can be made available within 10 minutes of the contingency to restore the balance between supply and demand. 10-minute spinning OR, which is normally 25% of all 10-minute OR in the market, can only be offered by generators that are actually synchronized to the power grid. Finally, 30-minute OR can be offered by spinning or non-spinning resources that are available to provide energy within 30 minutes of activation.

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